Composites for controlled release of well treatment agents

ABSTRACT

A well treatment composite which allows for the slow release of one or more well treatment agents into a subterranean formation and/or a wellbore penetrating the formation has a nano-sized calcined porous substrate (adsorbent) of high surface area onto which is applied the well treatment agent. The composites are suitable for use in such well treatment operations as hydraulic fracturing and sand control.

This application is a divisional application of U.S. patent applicationSer. No. 13/094,186, filed on Apr. 26, 2011, now U.S. Pat. No.9,029,300, issued on May 12, 2015.

FIELD OF THE INVENTION

Composites containing at least one well treatment agent and a calcinedporous metal oxide may be used in well treatment operations in order toslowly release the well treatment into the surrounding environment.

BACKGROUND OF THE INVENTION

Fluids produced from wells typically contain a complex mixture ofcomponents including aliphatic hydrocarbons, aromatics, hetero-atomicmolecules, anionic and cationic salts, acids, sands, silts and clays.The nature of these fluids combined with the severe conditions of heat,pressure, and turbulence to which they are often subjected, arecontributory factors to scale formation, salt formation, paraffindeposition, emulsification (both water-in-oil and oil-in-water), gashydrate formation, corrosion, asphaltene precipitation and paraffinformation in oil and/or gas production wells and surface equipment. Suchconditions, in turn, decrease permeability of the subterranean formationand thus reduce well productivity. In addition, such conditions shortenthe lifetime of production equipment. In order to clean deposits fromwells and equipment it is necessary to stop the production which is bothtime-consuming and costly.

Well treatment agents are often used in production wells to prevent thedeleterious effects caused by such deposits and precipitates. Forinstance, scaling in the formation (as well as in production linesdownhole) is often controlled by the use of scale inhibitors.

Several methods are known in the art for introducing well treatmentagents into production wells. For instance, a liquid well treatmentagent may be forced into the formation by application of hydraulicpressure from the surface which forces the treatment agent into thetargeted zone. In most cases, such treatments are performed at downholeinjection pressures below that of the formation fracture pressure.Alternatively, the delivery method may consist of placing a solid welltreatment agent into the producing formation in conjunction with ahydraulic fracturing operation. This method is often preferred becauseit puts the treatment agent in contact with the fluids contained in theformation before such fluids enter the wellbore where deleteriouseffects are commonly encountered.

A principal disadvantage of such methods is the difficulty in releasingthe well treatment agent into the well over a sustained period of time.As a result, treatments must repeatedly be undertaken to ensure that therequisite level of treatment agent is continuously present in the well.Such treatments result in lost production revenue due to down time.

Treatment methods have therefore been sought for introducing welltreatment agents into oil and/or gas wells wherein the treatment agentmay be released over a sustained period of time and wherein continuousattention of operators over prolonged periods is unnecessary.

U.S. Pat. No. 7,491,682 and U.S. Pat. No. 7,493,955 disclose methods oftreating a well by use of a composite containing a well treatment agentadsorbed onto high surface area solid carrier materials. Such compositesmay be used for the slow release of well treatment agents into theformation and the environs. They have been used in various formationsincluding deepwater, tight gas and coal bed methane formations. U.S.Pat. No. 7,686,081 and U.S. Patent Publication No. 2010/0175875 discloserecharging such particles once they are depleted.

Such composites, however, often have an inherent drawback in that theydo not exhibit the requisite strength of proppants and thus must usuallybe mixed at less than 10% by weight of the proppant in the fracture orsand control treatment. Higher loadings result in crushing of thecomposites translating into a loss of pack conductivity.

There is a need therefore for the development of well treatmentcomposites that exhibit the strength of a proppant and yet arecharacterized by a high surface area in order that loading of thecomposite in a proppant pack may be increased.

SUMMARY OF THE INVENTION

A well treatment composite may be used in stimulation of a well by beingintroduced into a subterranean formation or into the wellborepenetrating the subterranean formation. The well treatment compositeexhibits the strength of a conventional proppant yet allows for the slowrelease of one or more well treatment agents into the formation and/orwellbore. In some instances, the well treatment composite may be used asthe proppant per se.

The well treatment composite may be used in stimulation treatments as acomponent of a fracturing fluid or acidizing fluid, such as a matrixacidizing fluid. The composite has particular applicability incompletion fluids containing zinc bromide, calcium bromide calciumchloride and sodium bromide brines. Such fluids may be introduced downthe annulus of the well and, when desired, flushed with produced water.

The well treatment composite has a nano-sized calcined porous substrate(adsorbent) of high surface area onto which is applied the welltreatment agent. When used in an oil, gas or geothermal well or asubterranean formation penetrated by such a well, the well treatmentagent is slowly released from the adsorbent and may be slowly releasedinto a proppant pack.

Suitable substrates are calcined metal oxides and include alumina,zirconium oxide and titanium oxide.

In a particularly preferred embodiment, the composites of the inventionare used in wells in order inhibit the formation of scales, control theformation of scales or retard the release of scale inhibitors into thewell. For instance, the composite may be used in completion orproduction services. The composites of the invention may be used in thewell to remove undesired contaminants from or control the formation ofundesired contaminants onto tubular surface equipment within thewellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in thedetailed description of the present invention, a brief description ofeach drawing is presented, in which:

FIG. 1A and FIG. 1B are release profiles of a scale inhibitor in a highstrength composites containing porous alumina adsorbents between 0 to2,500 pore volumes and 0 to 10,000 pore volumes, respectively.

FIG. 2 is a release profile of a scale inhibitor in high strengthcomposites containing porous alumina adsorbent of varying diameterbetween 0 to 2,000 pore volumes.

FIG. 3 is a release profile of a scale inhibitor in high strengthcomposites containing porous alumina adsorbent of varying diameter usinga sand pack using 50% of the particles as in FIG. 2.

FIG. 4A and FIG. 4B are release profiles of a scale inhibitor in highstrength composites containing porous alumina adsorbents of varyingdiameters and sizes between 0 to 4,000 pore volumes and 0 to 10,000 porevolumes, respectively.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The well treatment composite for use in the treatment of wells or asubterranean formation is characterized by a calcined porous substrateprepared from nano-sized material onto which may be adsorbed at leastone well treatment agent.

The porosity and permeability of the calcined porous substrate is suchthat the well treatment agent may also be absorbed into the interstitialspaces of the porous substrate. Typically, the surface area of thecalcined porous substrate is between from about 1 m²/g to about 10 m²/g,preferably between from about 1.5 m²/g to about 4 m²/g, the diameter ofthe calcined porous substrate is between from about 0.1 to about 3 mm,preferably between from about 150 to about 1780 micrometers, and thepore volume of the calcined porous substrate is between from about 0.01to about 0.10 cc/g.

The well treatment agent is generally capable of being dissolved at agenerally constant rate over an extended period of time in the aqueousfluid water or hydrocarbon liquid contained in the subterraneanformation.

Typically, the specific gravity of the well treatment composite is lessthan or equal to 3.75 g/cc.

The porous metal oxide is typically spherical and insoluble in wellfluids under subterranean conditions, such as at temperatures less thanabout 250° C. and pressures less than about 80 MPa.

The porous substrate may be a metal oxide, such as alumina, zirconiumoxide and titanium oxide. Typically, the porous substrate is alumina.

The adsorbent may be prepared by:

-   (a) mixing a metal oxide hydrosol (such as aluminum oxide hydrosol)    containing a hydrate of the metal oxide or activated metal (such as    activated alumina) and an additive component selected from carbon    (such as carbon black) or a high molecular weight natural organic    material (such as wood flour and starch) which is insoluble in    aqueous solution up to a temperature of 50° C. and carbon with a    solution of hydrolyzable base to form a mixture;-   (b) introducing the mixture in dispersed form into a    water-immiscible liquid having a temperature of from about 60° to    100° C., whereby gel particles are formed;-   (c) aging the gel particles in the liquid at the temperature and    subsequently in an aqueous base, such as an aqueous ammonia    solution;-   (d) recovering the aged particles; and then-   (e) calcining the recovered particles. During calcination, the    additive component is removed. The calcined particles have a lower    bulk density when the additive component is present during    calcinations than when the additive component is not present.    Typically, the bulk density of the well treatment composite is    between from about 75 to about 150 lb/ft³. In addition, combustion    of the additive component during calcinations of the hydrosol    results in formation of pores of the calcined metal oxide.

The metal oxide hydrosol may optionally contain a silica-containingsubstance which in their non-soluble form is coprecipitated with themetal oxide particles. The silica-containing substance is preferably alow density silica, such as that prepared by hydrolysis of silicontetrachloride in an oxyhydrogen flame and known under the designationpyrogenic silica.

In an embodiment, spherical metal oxide adsorbent may be prepared from aconcentrated metal oxide hydrosol of a pH value in the range of about 3to about 5 which, in turn, is prepared by dissolving metal inhydrochloric acid and/or metal chloride in aqueous solution or bydissolving metal hydroxychloride in water, the concentration of which isadjusted so that metal oxide derived from the sol amounts to 15 to 35%by weight, preferably to 20 to 30% by weight of the mass of the calcinedparticles. Metal oxide hydrate and/or activated metal, preferably of anaverage particle diameter of maximally 10 g, is then added to thehydrosol in an amount so that the metal oxide content amounts to 65 to85% by weight, preferably 70 to 80% by weight of the calcined particles.Optionally, pyrogenic silica may be added to the hydrosol such that theSiO₂ content of the calcined particles amounts to 10 to 40% by weight. Asoft to medium-hard wood flour may then added to the mixture, the woodflour being ground to a finer particle size such that it is present in aquantity of 5 to 35% by weight, preferably 10 to 25% by weight relativeto the mass of the calcined particles. The hydrosol containing the woodflour may then be mixed with a concentrated aqueous solution ofhexamethylene tetramine and then sprayed or dropped into a column filledwith the mineral oil of a temperature of 60° C. to 100° C. The gelparticles are then allowed to remain at the temperature of precipitationfor a period of time from 4 to 16 hours; thereafter the gel particlesare aged for 2 to 8 hours in aqueous ammonia solution, washed withwater, dried at 100° C. to 150° C., or preferably at from about 120° C.to about 200° C., preheated to 250° C. to 400° C. and calcined at atemperature of 600° C. to about 1000° C.

Alternative methods for making metal oxide adsorbent are furtherdisclosed in U.S. Pat. No. 4,013,587, herein incorporated by reference.

In a preferred embodiment, when the metal oxide adsorbent is aluminaadsorbent, the adsorbent may be prepared by hydrolyzing aluminumalkoxides to render nano sized alumina, drying to remove water and thenintroducing the dried aluminum in a dispersed form into an oil at atemperature of from about 60° to 100° C., whereby gel particles areformed. The gel particles are then aged in the liquid and subsequentlyin an aqueous ammonia solution, recovered and then calcined. Nano sizedalumina may be produced having an average diameter in the range fromabout 0.4 mm to about 1 mm.

The amount of well treatment agent in the composite is normally fromabout 1 to 50 weight percent, preferably from about 14 to about 40weight percent.

The well treatment agent is preferably water soluble or soluble inaliphatic and aromatic hydrocarbons. When fluid is produced, the welltreatment agent may desorb into its respective solubilizing liquid. Forinstance, where a solid well treatment is an inhibitor for scales,corrosion, salts or biocidal action, the treatment agent may desorb intoproduced water. In the absence of water flow, the well treatment agentmay remain intact on the solid adsorbent. As another example, solidinhibitors for paraffin or asphaltene may desorb into the hydrocarbonphase of produced fluid.

In a preferred embodiment, the well treatment agent may be at least onemember selected from the group consisting of demulsifying agents (bothwater-in-oil and oil-in-water), corrosion inhibitors, scale inhibitors,paraffin inhibitors, gas hydrate inhibitors, salt formation inhibitorsand asphaltene dispersants as well as mixtures thereof.

Further, other suitable treatment agents include foaming agents, oxygenscavengers, biocides and surfactants as well as other agents whereinslow release into the production well is desired.

Adsorption of the well treatment agent onto the adsorbent reduces (oreliminates) the amount of well treatment agent required to be insolution. Since the well treatment agent is adsorbed onto a substrate,only a small amount of well treatment agent may be released into theaqueous medium.

The well treatment agent is preferably a liquid material. If the welltreatment agent is a solid, it can be dissolved in a suitable solvent,thus making it a liquid.

The composites defined herein are used in well treatment compositionssuch as fluids used for the treatment of gas wells or oils wells whereinit is desired to inhibit the formation of undesired contaminants,control the formation of undesired contaminants or retard the release ofundesired contaminants into the well. For instance, the composite may beused in completion or production services. The composites of theinvention may be used in the well to remove undesired contaminants fromor control the formation of undesired contaminates onto tubular surfaceequipment within the wellbore.

In a preferred embodiment, the well treatment composite of the inventioneffectively inhibits, controls, prevents or treats the formation ofinorganic scale formations being deposited in subterranean formations,such as wellbores, oil wells, gas wells, water wells and geothermalwells. The composites of the invention are particularly efficacious inthe treatment of scales of calcium, barium, magnesium salts and thelike, including barium sulfate, calcium sulfate, and calcium carbonatescales. The composites may further have applicability in the treatmentof other inorganic scales, such as zinc sulfide, iron sulfide, etc.

The well treatment composite may also be used to control and/or preventthe undesired formation of salts, paraffins, gas hydrates, asphaltenesas well as corrosion in formations or on surface equipment. Further,other suitable treatment agents include foaming agents, oxygenscavengers, biocides, emulsifiers (both water-in-oil and oil-in-water)and surfactants as well as other agents may be employed with theadsorbent when it is desired to slowly slow release such agents into theproduction well.

Suitable scale inhibitors are anionic scale inhibitors.

Preferred scale inhibitors include strong acidic materials such as aphosphonic acid, a phosphoric acid or a phosphorous acid, phosphateesters, phosphonate/phosphonic acids, the various aminopoly carboxylicacids, chelating agents, and polymeric inhibitors and salts thereof.Included are organo phosphonates, organo phosphates and phosphate estersas well as the corresponding acids and salts thereof.

Phosphonate/phosphonic acid type scale inhibitors are often preferred inlight of their effectiveness to control scales at relatively lowconcentration. Polymeric scale inhibitors, such as polyacrylamides,salts of acrylamido-methyl propane sulfonate/acrylic acid copolymer(AMPS/AA), phosphinated maleic copolymer (PHOS/MA) or sodium salt ofpolymaleic acid/acrylic acid/acrylamido-methyl propane sulfonateterpolymers (PMA/AMPS), are also effective scale inhibitors. Sodiumsalts are preferred.

Further useful, especially for brines, are chelating agents, includingdiethylenetriaminepentamethylene phosphonic acid andethylenediaminetetra acetic acid.

The well treatment agent may further be any of the fructans or fructanderivatives, such as inulin and inulin derivatives, as disclosed in U.S.Patent Publication No. 2009/0325825, herein incorporated by reference.

Exemplary of the demulsifying agents that are useful include, but arenot limited to, condensation polymers of alkylene oxides and glycols,such as ethylene oxide and propylene oxide condensation polymers ofdi-propylene glycol as well as trimethylol propane; and alkylsubstituted phenol formaldehyde resins, bis-phenyl diepoxides, andesters and diesters of the such di-functional products. Especiallypreferred as non-ionic demulsifiers are oxyalkylated phenol formaldehyderesins, oxyalkylated amines and polyamines, di-epoxidized oxyalkylatedpolyethers, etc. Suitable oil-in-water demulsifiers include polytriethanolamine methyl chloride quaternary, melamine acid colloid,aminomethylated polyacrylamide etc.

Paraffin inhibitors useful for the practice of the present inventioninclude, but are not limited to, ethylene/vinyl acetate copolymers,acrylates (such as polyacrylate esters and methacrylate esters of fattyalcohols), and olefin/maleic esters.

Exemplary corrosion inhibitors useful for the practice of the inventioninclude but are not limited to fatty imidazolines, alkyl pyridines,alkyl pyridine quaternaries, fatty amine quaternaries and phosphatesalts of fatty imidazolines.

Gas hydrate treating chemicals or inhibitors that are useful for thepractice of the present invention include but are not limited topolymers and homopolymers and copolymers of vinyl pyrrolidone, vinylcaprolactam and amine based hydrate inhibitors such as those disclosedin U.S. Patent Publication Nos. 2006/0223713 and 2009/0325823, both ofwhich are herein incorporated by reference.

Exemplary asphaltene treating chemicals include but are not limited tofatty ester homopolymers and copolymers (such as fatty esters of acrylicand methacrylic acid polymers and copolymers) and sorbitan monooleate.

Suitable foaming agents include, but are not limited to, oxyalkylatedsulfates or ethoxylated alcohol sulfates, or mixtures thereof.

Exemplary surfactants include cationic, amphoteric, anionic and nonionicsurfactants. Included as cationic surfactants are those containing aquaternary ammonium moiety (such as a linear quaternary amine, a benzylquaternary amine or a quaternary ammonium halide), a quaternarysulfonium moiety or a quaternary phosphonium moiety or mixtures thereof.Suitable surfactants containing a quaternary group include quaternaryammonium halide or quaternary amine, such as quaternary ammoniumchloride or a quaternary ammonium bromide. Included as amphotericsurfactants are glycinates, amphoacetates, propionates, betaines andmixtures thereof. The cationic or amphoteric surfactant may have ahydrophobic tail (which may be saturated or unsaturated) such as aC₁₂-C₁₈ carbon chain length. Further, the hydrophobic tail may beobtained from a natural oil from plants such as one or more of coconutoil, rapeseed oil and palm oil.

Preferred surfactants include N,N,N trimethyl-1-octadecammoniumchloride: N,N,N trimethyl-1-hexadecammonium chloride; and N,N,Ntrimethyl-1-soyaammonium chloride, and mixtures thereof. Suitableanionic surfactants are sulfonates (like sodium xylene sulfonate andsodium naphthalene sulfonate), phosphonates, ethoxysulfates and mixturesthereof.

Exemplary oxygen scavengers include triazines, maleimides,formaldehydes, amines, carboxamides, alkylcarboxyl-azo compoundscumine-peroxide compounds morpholino and amino derivatives morpholineand piperazine derivatives, amine oxides, alkanolamines, aliphatic andaromatic polyamines.

The composite of the invention does not require excessive amounts ofwell treatment agents. The amount of well treatment agent in thecomposite is that amount sufficient to effectuate the desired resultover a sustained period of time and may be as low as 1 ppm. Generally,the amount of well treatment agent in the composite is from about 0.05to about 5 (preferably from about 0.1 to about 2) weight percent basedupon the total weight of the composite.

When placed into a well, the well treatment agent slowly dissolves at agenerally constant rate over an extended period of time in the water orhydrocarbons which are contained in the formation and/or well. Thecomposite therefore permits a continuous supply of the well treatmentagent into the targeted area. Generally, the lifetime of a singletreatment using the composite of the invention is between six and twelvemonths and may be in excess of 3 years depending upon the volume ofwater or hydrocarbons produced in the production well and the amount ofwell treatment agent bound to the calcined porous metal oxide.

Adsorption of the well treatment agent onto the porous metal oxide andinto the interstitial spaces of the oxide reduces (or eliminates) theamount of well treatment agent required to be in solution. In light ofthe physical interaction between the well treatment agent and porousmetal oxide, only a small amount of well treatment agent may be releasedinto the aqueous or hydrocarbon medium.

For instance, where the well treatment agent is a scale inhibitor, theamount of scale inhibitor released from the composite is that amountrequired to prevent, or to at least substantially reduce the degree of,scale formation. For most applications, the amount of scale inhibitorreleased from the well treatment composite may be as low as ppm. Costsof operation are therefore significantly lowered.

As the oilfield fluid passes through or circulates around the welltreatment composites, the well treatment agent slowly desorbs. In sodoing, the composites are characterized by time-release capabilities.Gradual desorption of the well treatment agents insures that they areavailable to produced fluids for extended periods of time, typicallyextending for periods of time greater than a year and even as long asfive years. Typically the resulting concentration of the well treatmentagent in the wellbore is between from about 1 to about 50 ppm and may beas low as 1 ppm. Such small amounts of well treatment agent may besufficient for up to 1,000 pore volumes.

The composites of the invention may be employed with carrier ortreatment fluids in order to facilitate placement of the composite to adesired location within the formation. In this regard, any carrier fluidsuitable for transporting the composite may be used. Well treatmentcompositions containing the composite may be gelled or non-gelled. Inone embodiment, the well treatment composites described herein may beintroduced or pumped into a well as neutrally buoyant particles in, forexample, a saturated sodium chloride solution carrier fluid or a carrierfluid that is any other completion or workover brine known in the art.Suitable carrier fluids include or may be used in combination withfluids have gelling agents, cross-linking agents, gel breakers,surfactants, foaming agents, demulsifiers, buffers, clay stabilizers,acids, or mixtures thereof.

The carrier fluid may be a brine (such as a saturated potassium chlorideor sodium chloride solution), salt water, fresh water, a liquidhydrocarbon, or a gas such as nitrogen or carbon dioxide. The amount ofcomposite present in the well treating composition is typically betweenfrom about 15 ppm to about 100,000 ppm depending upon the severity ofthe scale deposition. Suitable compositions include fracturing fluids,completion fluids, acidizing compositions, etc.

Well treatment compositions containing the composites may be used intreatment operations near the wellbore in nature (affecting nearwellbore regions) and may be directed toward improving wellboreproductivity and/or controlling the production of fracture proppant orformation sand. Particular examples include gravel packing and,frac-packs and water packs. Moreover, such particles may be employedalone as a fracture proppant/sand control particulate, or in mixtures inamounts and with types of fracture proppant/sand control materials, suchas conventional fracture or sand control particulates. In suchapplications, the composite may be used in conjunction with a proppantor sand control particulate.

Such proppants or sand control particulates may be a conventionalparticulate material employed in hydraulic fracturing or sand controloperations, e.g., sand ((having an apparent specific gravity (ASG), APIRP 60, of 2.65)) or bauxite (having an ASG of 3.55). Alternatively, theproppant or sand control particulate may be “relatively lightweight”,defined as a particulate that has an ASG (API RP 56) that is less thanabout 2.45, more preferably less than or equal to 2.0, even morepreferably less than or equal to 1.75, most preferably less than orequal to 1.25. Such different types of particulates may be selected, forexample, to achieve a blend of different specific gravities or densitiesrelative to the selected carrier fluid. For example, a blend of threedifferent particles may be selected for use in a water fracturetreatment to form a blend of well treatment particulates having threedifferent specific gravities, such as an ASG of the first type ofparticle from about 1 to less about 1.5; an ASG of the second type ofparticle from greater than about 1.5 to about 2.0; and ASG of the thirdtype of particle from about greater than about 2.0 to about 3.0; or inone specific embodiment the three types of particles having respectivespecific gravities of about 2.65, about 1.7 and about 1.2. In oneexample, at least one of the types of selected well treatmentparticulates may be selected to be substantially neutrally buoyant inthe selected carrier or treatment fluid.

In some instances, the well treatment composition may contain betweenfrom about 1 to about 99% by weight of proppant.

In other instances, the composite defined herein is sufficiently strongat high pressures to be used as a proppant in hydraulic fracturingoperations including temperatures in excess of 250° C. and pressures inexcess of 80 MPa.

For example, when used in hydraulic fracturing and/or sand controltreatments, the porous particulate may be selected so to exhibit crushresistance under conditions as high as 10,000 psi closure stress, API RP56 or API RP 60, generally between from about 250 to about 8,000 psiclosure stress.

The composites of the invention are particularly effective in hydraulicfracturing as well as sand control fluids such as water, salt brine,slickwater such as slick water fracture treatments at relatively lowconcentrations to achieve partial monolayer fractures, low concentrationpolymer gel fluids (linear or crosslinked), foams (with gas) fluid,liquid gas such as liquid carbon dioxide fracture treatments for deeperproppant penetration, treatments for water sensitive zones, andtreatments for gas storage wells.

When used in hydraulic fracturing, the composite may be injected into asubterranean formation in conjunction with a hydraulic fracturing fluidat pressures sufficiently high enough to cause the formation orenlargement of fractures. Since the particulates may withstandtemperatures greater than about 370° C. and closure stresses greaterthan about 8000 psi, they may be employed as the proppant particulate.Alternatively, the composite may be employed in conjunction with aconventional proppant. Since the porous particulate of the composite isinsoluble, the composite may continue to function as a proppant evenafter the well treatment agent has been completely leached out of thecomposite.

Fluids containing the well treatment composites may be used to optimizehydraulic fracture geometries and enhance well productivity. As anexample, the fluids may be used to achieve increased propped fracturelength in relatively tight gas formations. Choice of differentparticulate materials and amounts thereof to employ in such blends maybe made based on one or more well treatment considerations including,but not limited to, objective/s of well treatment, such as for sandcontrol and/or for creation of propped fractures, well treatment fluidcharacteristics, such as apparent specific gravity and/or rheology ofcarrier fluid, well and formation conditions such as depth of formation,formation porosity/permeability, formation closure stress, type ofoptimization desired for geometry of downhole-placed particulates suchas optimized fracture pack propped length, optimized sand control packheight, optimized fracture pack and/or sand control pack conductivityand combinations thereof. The fracturing fluid, to be used with thecomposite, exhibits high viscosity, so as to be capable of carryingeffective volumes of one or more proppants. It may include aqueous gelsand hydrocarbon gels.

The composite may further be advantageously employed in liquefied gasand foamed gas carrier fluids, such as liquid CO₂, CO₂/N₂, and foamed N₂in CO₂ based systems. In this regard, liquid CO₂ based fracturing jobcharacteristics, such as proppant amounts, proppant sizes, mixing andpumping methodologies, using relatively lightweight porous ceramicmaterials may be the same as employed for conventional proppants.

Further, a gravel pack operation may be carried out on a wellbore thatpenetrates a subterranean formation to prevent or substantially reducethe production of formation particles into the wellbore from theformation during production of formation fluids. The subterraneanformation may be completed so as to be in communication with theinterior of the wellbore by any suitable method known in the art, forexample by perforations in a cased wellbore, and/or by an open holesection. A screen assembly such as is known in the art may be placed orotherwise disposed within the wellbore so that at least a portion of thescreen assembly is disposed adjacent the subterranean formation. Aslurry including the composite and a carrier fluid may then beintroduced into the wellbore and placed adjacent the subterraneanformation by circulation or other suitable method so as to form afluid-permeable pack in an annular area between the exterior of thescreen and the interior of the wellbore that is capable of reducing orsubstantially preventing the passage of formation particles from thesubterranean formation into the wellbore during production of fluidsfrom the formation, while at the same time allowing passage of formationfluids from the subterranean formation through the screen into thewellbore. It is possible that the slurry may contain all or only aportion of the composite; the balance of the slurry may be anothermaterial, such as a conventional gravel pack particulate.

As an alternative to use of a screen, the composite may be used in anymethod in which a pack of particulate material is formed within awellbore that it is permeable to fluids produced from a wellbore, suchas oil, gas, or water, but that substantially prevents or reducesproduction of formation materials, such as formation sand, from theformation into the wellbore. Such methods may or may not employ a gravelpack screen, may be introduced into a wellbore at pressures below, at orabove the fracturing pressure of the formation, such as frac pack,and/or may be employed in conjunction with resins such as sandconsolidation resins if so desired.

The composite is typically sufficiently strong to be used as a proppantduring a hydraulic fracturing operation at high pressures. They mayfurther be used in conjunction with other well treatment agentsincluding non-porous proppant materials, such as sand.

When used in fracturing, the fluid may or may not contain a proppant.

In another embodiment, the calcined porous metal oxide of the compositemay be reactivated or recharged with the well treatment agent after atleast a portion of the well treatment agent has been depleted. Suchprocesses are disclosed in U.S. Pat. No. 7,686,081 and U.S. PatentPublication no. 2010/0175875, both of which are herein incorporated byreference.

In this procedure, an initial charge of the composite may be injectedinto the well bore in a conventional method, whether for fracturing orfor gravel packing. Such conventional methods include truck treating,continuous injection, or high pressure pumping, for example. Thedownhole matrix formed within the formation after the initial charge iscomprised of the well treatment agent on a water-insoluble adsorbent aspart of the sand matrix.

For gravel packing in a sand control method, the composite is placedadjacent to a subterranean formation to form a fluid-permeable matrixcapable of reducing or substantially preventing the passage of formationparticles from the subterranean formation into the well bore while atthe same time allowing passage of formation fluids from the subterraneanformation into the well bore.

When a screening device is employed, the screening device is placed inthe wellbore before the injection of the composite. The mixture isinjected such that it is packed around the exterior of the screeningdevice to provide a fluid-permeable matrix around the screening devicewhich is capable of reducing or substantially preventing the passage offormation particles from the subterranean formation into the wellborewhile at the same time allowing passage of formation fluids from thesubterranean formation into the wellbore. In addition, the screen itselfcan be packed with the well treatment composite.

Additional amount fluid containing the well treatment agent may beinjected into the formation anytime after the initial charge of welltreatment agent in the composite has at least partially depleted.Typically, the additional well treatment agent is introduced when thewell treatment agent adsorbed onto the adsorbent or within theinterstitial spaces of the composite has been substantially depleted andthe performance level of the well treatment agent in the composite hasbecome unacceptable.

The injection of additional well treatment agent may be carried out inthe same manner by which the initial composite was charged into thewellbore, and can be carried out in any conventional method of injectingfluids into a wellbore of an oil or gas well, as mentioned above. Thefluid which is injected will typically be comprised of the desired welltreatment agent(s) in a solution which further comprises a solvent. Therelative amounts of the solvent and treatment agent of the solution tobe injected into the wellbore will of course vary depending upon theagent and solvent involved, but will typically be of a solvent totreatment agent ratio in the range of about 10:90 to about 95:5, byweight. The solvent in one embodiment is xylene, toluene, or a heavyaromatic distillate or a mixture thereof. When a mixture of all ofxylene, toluene and heavy aromatic distillate is used, the relativeamounts of each solvent component can vary, but will be typically invariable weight ratios (xylene:toluene:heavy aromatic distillate) suchas 10:70:20, 20:70:10, 70:20:10 or 20:10:70. In another embodiment, thesolvent can be water (for water soluble well treatment agents).

After the injection step is carried out, the wellbore is pressurized fora time and under conditions sufficient to reactivate the downhole matrixin the formation. This pressurization of material in the wellbore andformation fracture is commonly referred to as a “squeeze.” Reactivationof the treatment agent downhole may occur through the squeeze process aslong as the activity of the treatment agent in the in-place matrix isincreased relative to the treatment agent activity of the matrix justprior to injecting the solution. The determination of whether thetreatment agent activity has increased relative to the activity of thatagent just prior to injection of the solution and completion of thesqueeze may be made through conventional residual analysis andcomparison of the same before and after the squeeze, and conventionalanalysis of the physical well parameters, e.g., the production rate ofthe well and well pressure.

The pressure to which the wellbore is pressurized in the squeeze processtypically will be a pressure below the fracturing pressure, and whenapplicable, below the pressure that would cause the gravel pack to breakup. In one embodiment of the invention, the pressure is in a range ofabout 500 to about 15000 psia. The duration for which the pressurecondition is applied to the well will vary, depending upon the ease offracturing, but will typically be in the range of about 2 to about 10hours.

In another embodiment, the well treatment composite may be used topre-pack a screen for use in gravel packed wells. In this embodiment,the composite is preferably placed as close to the point of equilibriumas possible in order to ensure the continuous release of the welltreatment agent throughout the producing flow stream. In this manner,the well treatment composite may be used as a preventative measure bystopping precipitation and deposition of the well treatment agent beforeit starts. Such alternatives are desired, for instance, when there is aneed to increase the amount of the solid well treatment agent that canbe placed in gravel packed wells there the amount of proppant or gravelplaced in the well is at a minimum. In addition, the well treatmentcomposites in prepacked screens may be used to increase the amount ofsolid substrate exposed during sand control. When used in sand control,screens prepacked with the well treatment composite may reduceintervention costs for remediation and further increases theeffectiveness of the operation. Preferably, however, the screen used isof a size to reduce plugging by formation fines migration.

The following examples are illustrative of some of the embodiments ofthe present invention. Other embodiments within the scope of the claimsherein will be apparent to one skilled in the art from consideration ofthe description set forth herein. It is intended that the specification,together with the examples, be considered exemplary only, with the scopeand spirit of the invention being indicated by the claims which follow.

All percentages set forth in the Examples are given in terms of weightunits except as may otherwise be indicated.

EXAMPLES Example 1

In accordance with the procedure set forth in U.S. Pat. No. 4,013,587,alumina spheres were prepared by hydrolyzing aluminum alkoxide. Theresulting spheres were then dried to remove the water. The driedaluminum was then dispersed into an oil at about 90° C. Gel particleswere formed.

Water insoluble spherical particles of greater than 95% alumina wererecovered as Sample A. The spherical alumina beads consisted of bohemitealumina (non calcined) having a 1 mm diameter, a pore volume of 0.5 cc/gand a surface area of 216 m2/g.

A portion of Sample A was calcined at 1200° C. for 2 hours to renderspherical beads of 1 mm diameter (Sample B) composed of alpha/deltatheta alumina and having a pore volume of 0.08 cc/g and a surface areaof 3 m²/g.

A portion of Sample A was calcined at 1400° C. for 2 hours to renderspherical beads of 1 mm diameter (Sample C) composed of alpha aluminaand having a pore volume of 0.03 cc/g and a surface area of 4 m²/g.

Example 2

Each of Sample A, Sample B and Sample C were added at different weightpercent loadings to commercial lightweight ceramic proppant,commercially available as CARBO LITE® from Carbo Ceramics Inc. ofDallas, Tex., and the crush was determined according to ISO13503-2:Measurement of Properties of Proppants used in Hydraulic Fracturing andGravel Packing Operations). The results are shown in Table I belowwherein the Comparative Sample is a 10/50 mesh diatomaceous earth(Celite MP-79):

TABLE I CON- Comparative Sample A Sample B Sample C STRESS, CEN- SampleCRUSH CRUSH CRUSH psi TRATION CRUSH % % % % 4 0% 0.24 0.15 0.15 0.15 02% NA 0.68 0.36 0.32 0 4% NA 0.83 0.24 0.34 0 10% 5.88 3.16 0.61 0.39 60% 0.92 0.92 0.92 0.92 0 2% 2.77 2.09 1.09 1.09 0 4% 5.08 4.18 1.09 0.900 10% 11.49 9.57 1.48 1.46 8 0% 5.29 5.44 5.44 5.44 0 2% 7.14 8.38 6.225.61 0 4% 10.23 9.72 5.15 5.15 0 10% 17.21 17.30 5.44 5.03 1 0 0% NA12.32 12.32 12.32 0 2% NA 17.38 11.25 12.20 0 4% NA 22.31 14.12 9.96 010% NA 24.98 12.56 11.45The results indicate that the non-calcined Sample A has strengthcomparable to the diatomaceous earth of the Comparative Sample, whereascalcined Sample B and Sample C had the strength of commercial ceramicproppant in that even after the addition of 10% by weight of Sample B orSample C the crush strength of the combined proppant particle mixtures,even at 10,000 psi stress, was not altered.

Example 3

Scale inhibitor amino tri(methylene phosphonic acid) (ATMP),commercially available as Dequest 2000 from ThermPhos International BVwas adsorbed onto each of Sample A, Sample B and Sample C to renderSamples FBG-90706-4A, FBG-90706-4B and FBG-90706-4C respectively. TheseSamples were prepared by first adsorbing water on the Samples todetermine how much water could be adsorbed. Water was added to thesample until the Sample appeared wet. Sample A was found to adsorb 0.698g of H₂O/g of sample, Sample B adsorbed 0.362 g of H₂O/g of sample, andSample C adsorbed 0.415 g of H₂O/g of sample. Next Dequest 2000 wasadded to each sample. Due to the low adsorbency compared to diatomaceousearth, two additions were followed to prepare the samples. In the firstaddition for Sample A, only 0.32 g of Dequest 2000/g of Sample A couldbe added. In the second addition, 0.25 g of Dequest 2000/g of Sample Acould be added. This results in a product which contains about 22%active content. The method used to prepare the diatomaceous earth basedproduct set forth in U.S. Pat. No. 7,493,955 was adapted to thesealumina samples. For Sample B, only 0.31 g of Dequest 2000/g of Sample Bcould be added followed by 0.13 g of Dequest 2000/g of Sample B in thesecond addition. This results in a product which contains about 18%active content. For Sample C, only 0.23 g of Dequest 2000/g of Sample Ccould be added followed by 0.08 g of Dequest 2000/g of Sample C in thesecond addition. This results in a product which contains about 13.5%active content. The properties of each of these samples is set forth inTable II below:

TABLE II FBG FBG FBG 90607-4A 90607-4B 90607-4C Alumina Sample A SampleB Sample C Nominal Content % by weight 22 18 13.5 Determined 19.6 15.512.0 Content Bulk Loose lb/ft3 36 81 97 Density Packed 43 90 105Specific gravity H2O = 1 4.22 3.50 3.43 pH 10% Slurry 2.16 1.65 1.76

Example 4

The elution characteristic of the solid composites of Example 3 weredetermined by packing 20/40-mesh Ottawa sand and solid inhibitor (2% byweight of the sand) into a 35-cm-long stainless steel column (innerdiameter=1.08 cm). The pore volume was approximately 12 mL. The columnwas eluted with synthetic brine (0.025 mol/L CaCl₂, 0.015 mol/L NaHCO₃,1 mol/L NaCl, sparged with 100% CO₂) at 60° C. with a flow rate of 120mL/hour. The synthetic brine was at saturation with calcite to simulatetypical connate brine in the formation. The effluent solution wascollected and analyzed for phosphorus and Ca concentration to obtain theinhibitor release profile. The results are shown in FIG. 1A and FIG. 1B.The minimum effective concentration for scale inhibition was 0.1 ppm.

Example 5

Five alumina samples labeled 23A, 23B, 23C, 23D and 23E were prepared.23-A was the same as Sample A (1 mm alumina bead, not calcined); 23-Bwas the same as Sample B (1 mm alumina beads calcined at 1200° C. for 2hours) and 23-C was the same as Sample C (1 mm alumina bead calcined at1400° C. for 2 hours). Samples 23D and 23E were prepared using the sameprotocols as Sample B and Sample C, respectively, except the diameter ofthe spherical beads was adjusted to 0.8 mm. Each of 23A, 23B, 23C, 23Dand 23E were heated to 225° F. and cooled to room temperature in adesiccator before the addition of the ATMP solution. A 55% by weightsolution of ATMP was prepared. Three additions were made to each sampleand the amount that was able to be adsorbed is set forth in Table IIIbelow:

TABLE III % ATMP g 1st g 2nd g 3rd by weight g Alumina Addition AdditionAddition sample 23A 50.001 3.00 3.25 0.84 7.2 23B 50.005 9.43 6.52 1.3416.0 23C 50.004 5.29 1.83 0.70 7.9 23D 50.008 9.81 9.10 3.98 20.1 23E50.006 9.93 3.80 2.02 14.8The results shown in Table III are in contrast to 22.1% for Sample A,18.1% for Sample B and 13.5% for Sample C.

Example 6

The elution of Samples 22B, 23C, 23D, 23E and the Comparative Sample ofExample 2 were performed as set forth by the method in Example 4 with 2%of the particles by weight of the sand in the column. The results areshown in FIG. 2. The results are similar to those illustrated in FIG. 1Aand FIG. 1B. Since there is commercial interest in using higherpercentage of the particles in a proppant pack, the elution studies wereperformed on the samples at 50% of the particles in the sand pack andthe results are shown in FIG. 3. FIG. 3 indicates much slower releaseand longer period of effective inhibition.

Example 7

Four samples were prepared of two different sizes (0.8 mm and 1.0 mmdiameter before calcining) in accordance with the procedure set forth inExample 1. The four samples were labeled as CO10118 (0.8 mm), CO10118 (1mm), CO10524 (0.8 mm) and CO10593 (1 mm). Sample CO10118, aftercalcining, had a size of 25 mesh (0.71 mm) and a surface area of lessthan 1 m²/g. Sample CO10524, after calcining, had a size of 30 mesh(0.59 mm) and a surface area of 5.6 m²/g and sample CO10593, aftercalcining, had a size of 20 mesh (0.84 mm) and a surface area of 7.3m²/g. Crush analysis was conducted on each of the samples as well as onECONOPROP®, a commercial proppant available from Carbo Ceramics Inc.Further, two other samples labeled 25 mesh APA1.0/3C 12853 (surface area3.1 m²/g) and 30 mesh APA0.8/3C 12852 were also prepared. The crush dataon these is presented also in Table 4. The crush data of each sample wasgenerated using a pluviation method to load the proppant in the APIcrush cell. The results are shown in Table IV below:

TABLE IV Crushed Fines % 6000 Sample 5000 psi psi 8000 psi 10000 psi 25Mesh 0.8 mm C010118 0.5 0.8 1.9 8.4 (Surface Area: 1 m²/g) 30 Mesh 1.0mm C010118 5.2 5.9 11.8 18.9 (Surface Area: <1 m²/g) 30 Mesh 0.8 mmC010524 9.0 12.1 24.6 37.6 (Surface Area: 5.6 m²/g) 20 Mesh 1.0 mmC010593 26.6 36.5 49.2 61.4 (Surface Area: 7.3 m²/g) 25 Mesh EconoPropNA NA 21.5 24.9 30 Mesh EconoProp 11.1 12.2 15.0 20.6 25 Mesh APA 1.0/3C12853 1.2 2.2 8.6 17.5 (Surface Area: 3.1 m²/g) 30 Mesh APA 0.8/3C12852 0.7 1.5 4.4 11.6 (Surface Area: 3.1 m²/g) 25 Mesh EconoProp NA NA21.4 26.0 30 Mesh EconoProp 4.9 5.3 10.1 14.7

Example 8

Scale Inhibitor amino tri(methylene phosphonic acid) (ATMP),commercially available as Dequest 2000 from ThermPhos International BVwas adsorbed onto the four samples of Example 7 and resultant materialswere labeled FBG-100824A, FBG-100824B, FBG-100824C and FBG-100824D,respectively. The procedure for the preparation of these samples is setforth above in Example 3. The properties for each of the samples is setforth in Table V below:

TABLE V Sample FBG 100824 A FBG 100824 B FBG 100824 C FBG 100824 DAlumina CO10118, CO10524, CO10593, CO10118, 0.8 mm 0.8 mm 1 mm 1 mmCalculated Content ATMP 17.7 38.5 40.5 26.2 Determined Content % by 9.716.7 20.6 13.2 weight Bulk Loose lb/ft3 106 88 87 100 Density packed 11494 94 108 Specific gravity H2O = 1 3.19 2.94 2.87 3.11 Moisture % by0.41 0.50 0.51 0.48 weight

Example 9

The elution of each of samples of Example 8 was performed in accordancewith the procedures set forth in Examples 4 and 6 with 50% of theparticles by weight of the sand in the column. The results are set forthin FIG. 4A and FIG. 4B and are compared to the results of 2% of loadingof the composite exemplified in U.S. Pat. No. 7,493,955. The results aresimilar to those of Example 6 and show that the amount of composite maybe tailored with the amount of proppant depending on the amount of waterproduced from the well and how long protection is desired. Asillustrated, 2% of the particles in the sand and 50% particles in thesand may be used for the same purpose.

From the foregoing, it will be observed that numerous variations andmodifications may be effected without departing from the true spirit andscope of the novel concepts of the invention.

What is claimed is:
 1. A method of treating a subterranean formationpenetrated by a well which comprises pumping into the well a fluidhaving a well treatment composite comprising a well treatment agent andcalcined porous metal oxide wherein the porosity and permeability of thecalcined porous metal oxide is such that the well treatment agent isabsorbed into the interstitial spaces of the porous metal oxide andfurther wherein (a) the surface area of the calcined porous metal oxideis between from about 1 m²/g to about 10 m²/g; (b) the diameter of thecalcined porous metal oxide is between from about 0.1 to about 3 mm; and(c) the pore volume of the calcined porous metal oxide is between fromabout 0.01 to about 0.10 g/cc.
 2. The method of claim 1, wherein themetal oxide has been calcined at temperatures greater than or equal to1200° C.
 3. The method of claim 1, wherein the porous metal oxide isalumina.
 4. The method of claim 1, wherein the well treatment agent iswater soluble.
 5. The method of claim 1, wherein the well treatmentagent is hydrocarbon soluble.
 6. The method of claim 1 wherein thecomposite contains between from about 1 to about 50 weight percent ofthe well treatment agent.
 7. The method of claim 1, wherein the porousmetal oxide constitutes an adsorbent for the well treatment agent andfurther wherein the adsorbent contains silica.
 8. The method of claim 1,further comprising introducing well treatment agent into the well afterat least a portion of the well treatment agent on the composite has beendepleted in order to recharge or reactivate the calcined porous metaloxide of the composite.
 9. The method of claim 1, wherein thesubterranean formation is stimulated by pumping the well treatmentcomposite into the well.
 10. The method of claim 1, wherein theformation is subjected to hydraulic fracturing by pumping a fluidcontaining the well treatment composite into the well at a pressuresufficient to initiate or enlarge a fracture.
 11. The method of claim 1,wherein the treatment of the formation is a sand control operation. 12.The method of claim 10, wherein the well treatment composite is aproppant and further wherein no greater than 15% of the proppant iscrushed at closure stresses of 10,000 psi when the composite contains 10weight percent of well treatment agent.
 13. The method of claim 1,wherein the crush strength of the well treatment composite containing10% by weight of well treatment agent at 10,000 psi is substantially thesame as the crush strength of the porous metal oxide without the welltreatment agent.
 14. A method of inhibiting or controlling the rate ofrelease of a well treatment agent in a subterranean formation or in awell by introducing into the formation or well a well treatmentcomposite comprising a well treatment agent and calcined porous metaloxide wherein the porosity and permeability of the calcined porous metaloxide is such that the well treatment agent is absorbed into theinterstitial spaces of the porous metal oxide and further wherein (a)the surface area of the calcined porous metal oxide is between fromabout 1 m²/g to about 10 m²/g; (h) the diameter of the calcined porousmetal oxide is between from about 0.1 to about 3 mm; and (c) the porevolume of the calcined porous metal oxide is between from about 0.01 toabout 0.10 gee and wherein the composite has a lifetime, from a singletreatment, of at least six months.
 15. The method of claim 14, whereinthe porous metal oxide is alumina.
 16. The method of claim 14, whereinthe well treatment agent is selected from the group consisting of scaleinhibitors, corrosion inhibitors, paraffin inhibitors, salt formationinhibitors, asphaltene dispersants and mixtures thereof.
 17. The methodof claim 14, further comprising introducing well treatment agent intothe well after at least a portion of the well treatment agent on thecomposite has been depleted in order to recharge or reactivate thecalcined porous metal oxide of the composite.
 18. A method of treating asubterranean formation penetrated by a well which comprise pumping intothe well a fluid comprising a water soluble or hydrocarbon soluble welltreatment agent and calcined porous metal oxide wherein the porosity andpermeability of the calcined porous metal oxide is such that the welltreatment agent is adsorbed onto the surface of the calcined porousmetal oxide or absorbed into the interstitial spaces of the calcinedporous metal oxide and further wherein the well treatment compositecontains between from about 1 to about 50 weight percent of the welltreatment agent which is capable of being desorbed at a generallyconstant rate over an extended period of time in the formation fluidcontained in the subterranean forrmation.
 19. The method of claim 18,wherein the porous metal oxide is alumina.
 20. The method of claim 18,wherein at least one of the following conditions apply: a. the surfacearea of the calcined porous metal oxide is between from about 1 m²/g toabout 10 m²/g; b. the diameter of the calcined porous metal oxide isbetween from about 0.1 to 3 mm; and c. the pore volume of the calcinedporous metal oxide is between from about to about 0.10 cc/g; d. the bulkdensity of the composite is between from about 75 to about 150 lb/ft³;or e. the specific gravity of the well treatment composite is less thanor equal to 3.75 g/cc.